OIL AND GAS MIGRATION

OIL AND GAS MIGRATION Traditionally (Illing, 1933), the process of petroleum migration is divided into two parts: primary migration within the low-permeability source rocks secondary migration in permeable carrier beds and reservoir rocks. It is now recognized that fractured source rocks can also act as carrier beds and reservoir rocks so more modern definitions are: Primary migration of oil and gas is movement within the fine-grained portion of the mature source rock. Secondary migration is any movement in carrier rocks or reservoir rocks outside the source rock or movement through fractures within the source rock. Tertiary migration is movement of a previously formed oil and gas accumulation.

PRIMARY MIGRATION Primary oil migration within a fine-grained mature source rock with > 2% total organic carbon (TOC) occurs initially as a bitumen that decomposes to oil and gas and migrates as a hydrocarbon (HC) phase or phases. The process of HC generation causes expulsion of petroleum and is often a more potent mechanism for migration than mechanical compaction. Generation and expulsion of light oil, condensate and gas can come from low (< 2%) TOC source rocks without a bitumen intermediate. Type III kerogens are the most likely source. The migrating phase is HC. Migration can also occur in aqueous solution for the smallest and most soluble molecules (methane, ethane, benzene, toluene). Migration by diffusion is not significant.

PORE WATER SALINITY The salinity of pore waters in reservoirs typically increases by 6 to 160 g/l per km depth. The causes of increased salinity are: salt dissolution (primary) membrane filtration (secondary) Seawater salinity is about 35 g/l. Much higher salinities are found in oil field brines. Typical salinities for giant oil and gas reservoirs are 30 g/l for sandstones and 90 g/l for carbonates. Concentrations of total dissolved solids (TDS) range from 80 to 300 g/l in reservoirs deeper than 1 km.

SHALE POROSITY Under hydrostatic conditions, the change in porosities of shales below 30% tends to follow two distinctive stages. Stage 1: A linear or exponential decrease in porosity and density due to mechanical compaction down to a subsurface temperature of 90 to 110 o C Stage 2: An unchanging porosity and density indicating no further compaction. Depth (km) 0 1 Stage 1 2 3 Stage 2 4 0 10 20 30 40 Porosity (%)

POROSITY vs DEPTH Porosity reductions in stage 1 are mainly due to mechanical compaction should follow an exponential curve according to classical consolidation theory. A more linear trend is often observed. The minimum matrix porosity at the top of stage 2 ranges from 3 to 15% depending on the clay mineral composition. Low values correspond to quartz-rich shales with little illite or smectite content. Higher values correspond to clay-rich rocks. Slight porosity reductions in stage 2 can originate from cementation. Small increases can occur due to hydraulic fracturing. Porosities of sandstones and carbonates at depths > 3 km show much greater variability than shales, due to chemical diagenesis, cementation and dissolution.

PORE DIAMETERS Pores are classified by size: macropores > 50 nm mesopores 2 to 50 nm micropores < 2 nm Nitrogen desorption (2 to 50 nm) and mercury intrusion (3 to 300 nm) porosimetry are the principal methods available to determine pore size distributions. Median pore diameters of shale source rocks range from 5 to 20 nm with a corresponding porosity range of 4 to 15%. The effective molecular diameters of some HC products are: Molecule Diameter (nm) Water 0.30 Methane 0.38 n-alkanes 0.47 Cyclohexane 0.48 Complex aromatics 1-3 Asphaltenes 5-10

EXPULSION EFFICIENCY Shale source rocks act like sieves during primary migration. They preferentially release small paraffinic and naphthenic molecules and retain aromatic and asphaltic molecules. Small HC molecules can migrate through all but the smallest micropores. Large complex molecules are retained by small pores. Expulsion efficiency is a measure of the percentage of a particular hydrocarbon that can escape from the source bed during primary migration. 100 Expulsion Efficiency % 0 10 15 20 25 30 35 Carbon Number

PRIMARY MIGRATION MECHANISMS (1) Migration by Diffusion Diffusion is the spreading of HC as a result of a concentration gradient. This process leads to dispersal rather than accumulation. Diffusion rates in porous media are very low. Methane, the HC with the highest diffusion coefficient, is estimated to take 80 Ma to diffuse a distance of 1 km. Migration in Aqueous Solution Methane is widely distributed in the subsurface because of its solubility in pore fluids and its high mobility as a gas phase. Methane has a solubility of about 2500 mg/l at 100 o C and 50 MPa for a salinity of 150 g/l. Most other HCs have solubilities less than 50 mg/l in the petroleum generation window. Solubilities decrease with increasing pore fluid TDS, decreasing pressure and temperature, and increasing HC saturation.

PRIMARY MIGRATION MECHANISMS (2) Migration as Hydrocarbon Phases Most migration of petroleum takes place by flow of a hydrocarbon liquid or gaseous phase through microfractures in the source rock. Matrix permeabilities for source rocks range from 1 to 10-8 md or 10-15 to 10-23 m 2. These low values are unlikely to be sufficient for migration. A few microfractures can increase permeability by many orders of magnitude.. Consider a 1 km cube of shale with a permeability of 10-23 m 2. A single microfracture with a width of less than 5 µm would provide the same

flow. Microfractures with apertures from 5 to 500 µm are commonly observed in source rocks.

MULTI-COMPONENT SYSTEM CB CP P LIQUID LIQUID + GAS CT GAS T For a multi-component system, the bubblepoint line divides the liquid stability field from the liquid + gas field. The dew-point line divides the liquid + gas field from the gas stability field. The bubble-point (BPL) and dew-point (DPL) lines meet at the critical point (CP). CB = cricondenbar (max. P). CT = cricondentherm (max. T)

ISOTHERMAL PRODUCTION CB CP P LIQUID LIQUID + GAS CT GAS T Oil and Gas: Two phase oil and/or gas below CB. Retrograde Gas: Single phase wet gas between the CB and CT with liquid over part of the P-T path. Gas: Single phase dry gas above CT. P-T Path: Reducing both P-T moves from the gas to gas and condensate to liquid and gas fields.

GAS-PHASE MIGRATION As T and P increase, compressed gas can dissolve increasing amounts of heavy liquid hydrocarbons. At depth, the gas-phase can pick up significant quantities of liquid hydrocarbon. As the gas migrates upwards through microfractures, T and P are reduced and retrograde condensation leads to formation of an oil-phase. Gas-phase migration cannot account for giant oil accumulations (such as the Middle East) unless huge volumes of gas have been lost. Nevertheless, gas-phase migration is a reasonable explanation for accumulations in the Gulf Coast, Niger Delta, Mackenzie Delta, Mahakam Delta and the Po Basin.

OIL-PHASE MIGRATION Thermal stresses in source rocks (1.5 to 2.5% TOC) generate a continuous bitumen network within the pores from original kerogen. As temperature increases, the bitumen forms an oil that fills the micropores and is expelled into adjacent fractures. Bitumen and oil have lower densities than the original kerogen and a net volume increase occurs in the generation process, which causes expulsion of oil. Conversion of organic matter to liquid and gases can cause a net increase in volume of more than 25%. Oil and Condensate Gas Kerogen Kerogen Kerogen Increasing Maturation

SECONDARY MIGRATION The main force driving secondary migration is the buoyancy of hydrocarbons. There is a tendency for oil and gas to segregate from aqueous phase liquids because of density differences. In most cases, the action of gravity leads to a column of gas over oil over water. In a few cases, this does not happen and gravity migration is restricted by capillary forces. Capillary pressure is the excess pressure required for oil or gas to displace water from pores. If capillary and buoyancy forces are matched, hydrocarbon can be trapped within a particular lithology. Hydrodynamic traps of this kind are found in western Canada when gas is found downdip and below water saturated rocks.

FLUID PRESSURE Pressures at 1,000 m (1 km) depth and pressure gradients depend on the saturating fluid the porous medium densities. GAS OIL WATER BRINE ROCK P 2,000 8,300 9,800 11,600 22,000 kpa dp dh 2.0 8.3 9.8 11.6 22.0 kpa m

FLUIDS AND PRESSURE Pressure at any point in a static fluid is equal to the weight of the overlying fluid column: P = ρg.h = γh where P is the fluid pressure [F/L 2 ] ρ is the fluid density [M/L 3 ] h is the column height [L] γ is the fluid specific weight [F/L 3 ] The pressure gradient dp/dh is thus the specific weight, γ=ρg. Fluid specific gravities in reservoir engineering can range from 0.1 for shallow gas to 1.25 for saturated brines. Hydrocarbon gases range from 0.1 to 0.5, distillates from 0.5 to 0.75, oils from 0.75 to 1.0 and formation water from 1.0 to 1.25.

INTERFACIAL TENSION When a drop of one immiscible fluid is immersed in another and comes to rest on a solid surface the shape of the resulting interface is governed by the balance of adhesive and cohesive forces. AIR θ WATER SOLID SURFACE The surface area at the fluid-fluid contact is minimized by the interaction of these forces: cohesive forces at the fluid-fluid interface adhesive forces at the solid-fluid interface The interfacial tension represents the amount of work needed to create a unit surface area at the interface. The dimension of work is [FL] so interfacial tension is [FL/L 2 ] = [FL -1 ]. The SI units are N/m or J/m 2. Typical values are 0.02 to 0.03 N/m for oil-brine and quartz or calcite.

CONTACT ANGLE The angle between the fluid and solid phases is called the contact angle. Contact angles are always measured in the denser fluid phase. If θ < 90 0 the fluid is said to wet the surface. If θ > 90 0 the fluid is said to be non-wetting. AIR θ WATER MERCURY θ SOLID SURFACE adhesion > cohesion =>> wetting cohesion > adhesion =>> non-wetting Water wets glass, mercury is non-wetting on a glass surface. Interfacial tension creates a curved interface between two immiscible fluids.

CAPILLARY RISE P a P w 2r h Water rises in a capillary tube diameter, 2r, to a height, h. The downward force is thus: W = mg = ρ g.v = ρg.π r 2 h = π r 2.P c where P c = ρ gh is called the capillary pressure. P c = P a - P w The downward force of the water is resisted by the interfacial tension at the contact around the diameter of the tube: π r 2.P c = 2π r.σ wa.cosθ wa P c = 2σ wa.cosθ wa /r

CAPILLARY PRESSURE The effect of interfacial tension is to create a finite pressure difference between immiscible fluids called the capillary pressure: P c = P nw - P w where P w and P nw refer to the wetting and nonwetting phases. Capillary pressure depends on the properties of the fluids and solid surfaces, σ wa and cosθ wa, and the tube radius, r. When adhesion > cohesion, adhesive forces draw the fluid up the tube until they are balanced by the weight of the fluid column. When cohesion > adhesion, cohesive forces drag fluid down the tube until they are balanced by the weight of the head difference forcing fluid upwards.

WETTABILITY The wettability of a rock refers to the contact angle for the oil-brine interface. If θ < 90 0 the reservoir is said to be water-wet. If θ > 90 0 the reservoir is said to be oil-wet. In oilfield terminology: 0 o - 70 o strongly water-wet 70 o - 110 o intermediate wettability 110 o - 180 o strongly oil-wet Wettability is affected by factors including fluid compositions mineral surface properties microbial activity temperature and pressure

WATERFLOOD DISPLACEMENT WATER WET RESERVOIR OIL WET RESERVOIR

TYPICAL INTERFACIAL PROPERTIES Fluid-Fluid System * Contact Angle (Degrees) Interfacial Tension (N/m) Air-Mercury 140 0.485 Methane-Brine 0 0.072 <30 o API Oil-Brine 0 0.030 30 o -40 o API Oil-Brine 0 0.020 >40 o API Oil-Brine 0 0.015 * These results were obtained for a quartz solid surface. For a pore-throat diameters between 1 mm and 1 µm, we obtain the following capillary pressures: Fluid-Fluid System P c kpa P c kpa P c kpa P c kpa Pore-throat dia. (mm) 0.001 0.00 0.1 1.0 Methane-Brine 288 28.8 2.88 0.29 <30 o API Oil-Brine 120 12.0 1.20 0.12 30 o -40 o API Oil-Brine 80 8.0 0.80 0.08 >40 o API Oil-Brine 60 6.0 0.60 0.06

OIL-WATER TRANSITION ZONE P c h c OIL OIL + WATER h o WATER S w At elevations greater than the capillary head, h c, the oil saturation is (1 - S wi ). At the OWC, h o, the water saturation is 1. Between h o and h c the saturations vary continuously through the capillary transition zone.

INTERFACIAL TENSION CHANGES Interfacial tensions for oil-water systems range from 0.005 to 0.035 N/m at STP. With increasing temperature and pressure, typical values are 0.01 to 0.02 N/m. Gas-water systems range from 0.03 to 0.07 N/m at STP. With increasing temperature and pressure these values to around 0.022 to 0.025 N/m. This means that oil migrates more easily than gas through water-wet rock. The much higher buoyancy of gas combined with a low viscosity gives gas a considerably greater migration potential. At even higher T and P, interfacial tensions for oil-water and gas-water systems approach the same value (above the critical point for the system). The single-phase system exists as gas and condensate.

PORE THROATS The critical parameter controlling the value of P c is pore-throat radius. A hydrodynamic trap will be created at a change in pore-size if buoyancy cannot overcome capillary forces. A small opening in a water-wet reservoir rejects oil (and gas) whereas a small opening in an oil-wet rock rejects water. Most rocks are water-wet in the subsurface so capillary barriers to petroleum migration are common. Capillary pressures in shales with pore diameters of 20-50 nm can be massive. For example, for a light crude the value of P c would be 2400 to 6000 kpa or 24 to 60 atmospheres! Natural hydrofracturing limits the differential pressure that can be sustained. Microfractures often provide conduits for oil to pass matrix capillary barriers, for example, a 500 nm (0.5 mm) microfracture would only require 480 kpa provided by buoyancy to pass.

JOINTS AND FAULTS Macrofractures of one kind or another are pervasive in most brittle rocks. Tensile fractures and normal faults are most likely to provide flow conduits because the fractures tend to be more likely to be open. Fault breccias often provide zones of high permeability. Reverse faults tend to be less permeable than normal faults as would be expected from the stress regime responsible for their formation. Vertical migration of fluids through fracture systems in both low permeability rocks and reservoir rocks is widely reported in the hydrogeological and petroleum geology literature. Faults can also act as permeability barriers where clay gouge or other low permeability infill is produced by shearing.

UNCONFORMITIES Unconformities are usually associated with significant changes in permeabilities and may represent either flow barriers or conduits. Some petroleum geologists (North, 1985) believe that sub- and intra-cretaceous unconformities may be the most important structural phenomena involved in trapping oil and gas on a worldwide basis. In western Canada, where the sub-cretaceous unconformity is overlain by massive sheet sandstones (Mannville), the unconformity can be a permeable migration pathway. Unconformities often correspond to periods of subaerial erosion when permeability tends to be enhanced. A large number of oilfields are related to unconformities including both the Venezuelan and western Canadian heavy oil deposits.

TRAPS AND SEALS A trap is any part of a reservoir that holds commercial quantities of oil. The closure of a trap is the vertical distance from the crest or highest point to the spill point, where the oil spills below the trap into adjacent permeable beds. Seal Closure Crest Spill Point A seal is the low permeability interval above the trap. The gross pay zone in a trap is the distance from the top of the accumulation to the lowest point on the OWC. The net pay zone is the part of the gross pay interval that is commercially productive.

TRAP PROPERTIES The three most important properties of a trap are: 1. proximity to HC migration pathways 2. permeability of the seal 3. height of the closure (trap-size). If a trap is not situated on a migration pathway, it will not accumulate oil. Knowledge of regional paleoflows is critical to the exploration process. All seals leak. If the seal is too permeable, the trap the leakage rate may exceed the rate of migration and no accumulation will occur. If the closure is small, the accumulation may not be commercially viable. Small pools are difficult to find and expensive to develop.

SEAL PROPERTIES It is not the matrix permeability but the fracture permeability of a seal that is critical. Gas hydrates (permafrost) or regional evaporites (salt and anhydrite) are the best seals. Both gas hydrates and evaporites have the ability to heal fractures over time. Ductile shales (> 40% clay minerals) are better seals than more brittle fine-grained rocks. Only a small percentage of shales have clay-mineral contents as high as 40%. Most shales are brittle and are readily fractured on a microscopic scale. This is sufficient to render them ineffective as seals. Stylolites, formed by pressure solution, can at times provide effective seals in carbonates. Asphalt can also act as a seal where oil is degraded near surface and large HC molecules block pore-throats.

TRAP INTEGRITY Structural Traps In structural traps, such as simple anticlinal traps, the buoyant force tends to be directed vertically upwards and approximately normal to bedding. Sedimentary sequences tend to show vertical changes in lithology and a series of silts and shales can provide an effective seal. Stratigraphic Traps In a stratigraphic traps, such as a pinchout, the buoyant force is directed up-dip rather than vertically. A single thin silty layer in

pinchout can result in loss of seal integrity and no petroleum accumulation will take place.

SECONDARY MIGRATION DISTANCES About 60% of reservoirs worldwide appear to have accumulated due to vertical migration and 40% due to lateral migration from the source bed. In many cases, both lateral and vertical migration is involved. Migration distances depend on the size of the basin in which the oil accumulates. Basin Type Example % World Reserves Foreland Basin and Fold Belts Alberta 56 Interior Rift North Sea 23 Divergent Margin Gulf Coast 8 Active Margin Los Angeles 6 Deltas Mackenzie 6 Interior Cratonic Sag Williston 1 Vertical migration is more efficient than lateral migration but less petroleum is collected because traps can only intercept migration pathways vertically beneath themselves. Lateral migration can drain a larger volume of source rock.